1. Field of the Invention
The present invention relates to removable subassemblies in sealing equipment. Specifically, the invention relates to removable subassemblies in oil field rotary drilling head assemblies.
2. Description of the Related Art
Drilling an oil field well for hydrocarbons requires significant expenditures of manpower and equipment. Thus, constant advances are being sought to reduce any downtime of equipment and expedite any repairs that become necessary. Rotating equipment is particularly prone to maintenance as the drilling environment produces abrasive cuttings detrimental to the longevity of rotating seals, bearings, and packing glands.
FIG. 1 shows an exemplary drilling rig 10. The drilling rig 10 is placed over an area to be drilled and a drilling bit (not shown) is attached to sections of drill pipe 12. Typically, a rotary turntable 14 rotates a drive member 16, referred to as a kelly, which in turn is attached to the drill pipe 12 and rotates the drill pipe to drill the well. In some arrangements, a kelly is not used and the drill string is rotated by a drive unit (not shown) attached to the drill pipe itself. Typically, a mixture of drilling fluids, referred to as mud, is injected into the well to lubricate the drill bit (not shown) and to wash the drill shavings and particles from the drill bit and then return up through an annulus surrounding the drill pipe 12 and out the well through an outflow line 22 to a mud pit 24. New sections of drill pipe 12 are added to the drill pipe in the well using a crane 26 and a block and tackle 28 to collectively form a drill string 30 as the well is drilled deeper to the desired underground strata 32. A power unit 34 powers a control unit 36 and associated motors, pumps, and other equipment (not shown) mounted on a drilling platform 38.
In many instances, the strata 32 produce gas or fluid pressure which needs control throughout the drilling process to avoid creating a hazard to the drilling crew and equipment. To seal the mouth of the well, one or more blow out preventers (BOP) are mounted to the well and can form a blow out preventer stack 40. An annular BOP 42 is used to selectively seal the lower portions of the well from a tubular body 44 which allows the discharge of mud through the outflow line 22. A rotary drilling head 46 is mounted above the tubular body 44 and is also referred to as a rotary blow out preventer. An internal portion of the rotary drilling head 46 is designed to seal around a rotating drill pipe 30 and rotate with the drill pipe by use of a internal sealing element, referred to as a packer (not shown), and rotating bearings (also not shown) as the drill pipe is axially and slidably forced through the drilling head 46. However, the packer wears and occasionally needs replacement. Typically, the drill string or a portion thereof is pulled from the well and a crew goes below the drilling platform 38 and manually disassembles the rotary drilling head 46. Typically, a crane 26 is used to lift the rotary drilling head 46 which can weigh thousands of pounds. Because of the size of the drilling head 46, portions of the drilling platform 38 and equipment are disassembled to allow access to the drilling head and to remove the drilling head from the BOP stack 40. The drilling head 46 is replaced or reworked and crew goes below the drilling platform to reassemble the drilling head to the BOP stack 40 and operation is resumed. The process is time consuming and can be dangerous.
Prior efforts have sought to reduce the complexity of the drilling head replacement. For example, FIG. 2 is a schematic cross sectional view of a rotary blow out preventer, similar to the embodiments shown in U.S. Pat. No. 5,848,643, which is incorporated herein by reference. A rotating spindle assembly 48 is disposed within a non-rotating spindle assembly 50, which in turn, is disposed within a body 52 and held in position by lugs 54. To remove the entire non-rotating and rotating spindle assembly from the body 52, lugs 54 are rotated in horizontal grooves 56 and then lifted upwardly through vertical slots 58 in a “twist and lift” motion. However, the assembly can weigh about 1,500 to about 2,000 pounds and still requires use of extra lifting equipment such as the crane 26. In addition, disassembly of the drilling platform 38 is necessary to provide access and requires manual efforts by the drilling crew.
Similarly, U.S. Pat. No. 3,934,887, incorporated herein by reference, discloses a BOP body having an assembly of a lower stationary housing 22 and an upper stationary housing 24. The upper stationary housing 24 houses a stationary tapered bowl 60, a rotating bowl 62 disposed inwardly of the tapered bowl, and bearings 66, 68 disposed between the stationary bowl and rotating bowl. A stripper 40 is connected to the rotating bowl 62. A clamp 28 retains the assembly of the stationary tapered bowl 60, the rotating bowl 62, the bearings 66, 68, and associated equipment to the upper stationary housing 24. By unclamping the clamp 28, the entire assembly may be removed from the BOP body. However, the removable assembly is of such size and weight with the result that crews are needed below the drilling platform and lifting equipment is necessary to lift the assembly from the BOP body.
FIG. 3 is a schematic cross sectional view of another rotary BOP 60, similar to the embodiments disclosed in U.S. Pat. No. 4,825,938, incorporated herein by reference. To avoid removing the entire rotary BOP, the reference discloses a pneumatically actuated series of “dogs” 64 which engage a groove 66 on a retainer collar 68, referred to in that disclosure as “massive”. By actuating pneumatic cylinders 70 to rotate the dogs 64 away from the groove 66, the “massive” retainer collar 68, the stinger 72, stinger flange 74, a stripper rubber 76, and associated bearing surfaces 78, 80 and 82 can be removed and access gained to the inner structures to repair or replace the stripper rubber 76. This device is similar to the preceding references in that both rotating and non-rotating portions are removed, which add weight and size to the assembly that is removed.
Another challenge to the rotary drilling head maintenance is bearing life. In a rotary BOP, bearings are used to reduce the friction between the fixed portions of the drilling head and the rotating drill string with rotating portions of the drilling head. As shown in FIG. 2, the typical assembly includes a lower bearing 84 and an upper bearing 86 axially disposed between a rotating portion 48 and a non-rotating portion 50 of the rotary BOP 50. The bearings are tightened in position, referred to as pre-loading the bearing, by typically turning a threaded bearing retainer 88 until the bearings are pre-loaded to a desired level. As the bearings wear or otherwise change, the loading changes. The BOP must be disassembled, the bearing readjusted, and the BOP reassembled. Otherwise, the bearings can fail prematurely, causing downtime for the drilling operations. Typically, the bearing retainer is directly inaccessible after assembly into the drilling head and the drilling head must be at least partially disassembled for readjustment.
There remains a need for an apparatus and method for decreasing the downtime in drilling an oil well by decreasing the time required for removal and replacement/repair of the packer and decreasing the time required to adjust the bearing loading.